Note: Descriptions are shown in the official language in which they were submitted.
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ENHANCING THE START-UP OF RESOURCE RECOVERY PROCESSES
FIELD
[0001]
The present techniques relate to the use of well pairs to harvest
resources.
Specifically, techniques are disclosed for designing gravity drainage well
pairs to
increase the recovery of resources from a reservoir.
BACKGROUND
[0002]
This section is intended to introduce various aspects of the art, which
may be
associated with exemplary embodiments of the present techniques. This
discussion is
believed to assist in providing a framework to facilitate a better
understanding of
particular aspects of the present techniques. Accordingly, it should be
understood that
this section should be read in this light, and not necessarily as admissions
of prior art.
[0003]
Modern society is greatly dependent on the use of hydrocarbons for fuels
and
chemical feedstocks. Hydrocarbons are generally found in subsurface rock
formations
that can be termed "reservoirs." Removing hydrocarbons from the reservoirs
depends
on numerous physical properties of the rock formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
rock formations, and the proportion of hydrocarbons present, among others.
[0004]
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to satisfy future energy needs.
However, as the costs of
hydrocarbons increase, these less accessible sources become more economically
attractive. For example, the harvesting of oil sands to remove hydrocarbons
has
become more extensive as it has become more economical. The hydrocarbons
harvested from these reservoirs may have relatively high viscosities, for
example,
ranging from 8 API, or lower, to up to 20 API, or higher. Accordingly, the
hydrocarbons
may include heavy oils, bitumen, or other carbonaceous materials, collectively
referred
to herein as "heavy oil," which are difficult to recover using standard
techniques.
[0005]
Several methods have been developed to remove hydrocarbons from oil
sands. For example, strip or surface mining may be performed to access the oil
sands,
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which can then be treated with hot water or steam to extract the oil. However,
deeper
formations may not be accessible using a strip mining approach. For these
formations,
a well can be drilled to the reservoir and steam, hot air, solvents, or
combinations
thereof, can be injected to release the hydrocarbons. The released
hydrocarbons may
then be collected by the injection well or by other wells and brought to the
surface.
[0006] A number of techniques have been developed for harvesting heavy
oil from
subsurface formations using well-based recovery techniques. These operations
include
a suite of steam based in situ thermal recovery techniques, such as cyclic
steam
stimulation (CSS), steam flooding and steam assisted gravity drainage (SAGD)
as well
as surface mining and their associated thermal based surface extraction
techniques.
[0007] For example, CSS techniques include a number of enhanced recovery
methods for harvesting heavy oil from formations that use steam heat to lower
the
viscosity of the heavy oil. These steam assisted hydrocarbon recovery methods
are
described in U.S. Patent No. 3,292,702 to Boberg, and U.S. Patent No.
3,739,852 to
Woods, et al., among others. CSS and other steam flood techniques have been
utilized
worldwide, beginning in about 1956 with the utilization of CSS in the Mene
Grande field
in Venezuela and steam flood in the early 1960s in the Kern River field in
California.
[0008] The CSS process may raise the steam injection pressure above the
formation
fracturing pressure to create fractures within the formation and enhance the
surface
area access of the steam to the heavy oil, although CSS may also be practiced
at
pressures that do not fracture the formation. The steam raises the temperature
of the
heavy oil during a heat soak phase, lowering the viscosity of the heavy oil.
The injection
well may then be used to produce heavy oil from the formation. The cycle is
often
repeated until the cost of injecting steam becomes uneconomical, for instance
if the cost
is higher than the money made from producing the heavy oil. However,
successive
steam injection cycles reenter earlier created fractures and, thus, the
process becomes
less efficient over time. CSS is generally practiced in vertical wells, but
systems are
operational in horizontal wells.
[0009] Solvents may be used in combination with steam in CSS processes,
such as
in mixtures with the steam or in alternate injections between steam
injections. These
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techniques are described in U.S. Patent No. 4,280,559 to Best, U.S. Patent
No. 4,519,454 to McMillen, and U.S. Patent No. 4,697,642 to Vogel, among
others.
[0010] Cyclic enhanced recovery techniques have been developed that are
not
based on thermal methods. For example, U.S. Patent No. 6,769,486 to Lim, et
al.,
discloses a cyclic solvent process for heavy oil production. In the process, a
viscosity
reducing hydrocarbon solvent is injected into a reservoir at a pressure
sufficient to keep
the hydrocarbon solvent in a liquid phase. The injection pressure may also be
sufficient
to cause dilation of the formation. The hydrocarbon solvent is allowed to mix
with the
heavy oil at the elevated pressure. The pressure in the reservoir can then be
reduced
to allow at least a portion of the hydrocarbon solvent to flash, providing a
solvent gas
drive to assist in removing the heavy oil from the reservoir. The cycles may
be repeated
as long as economical production is achieved.
[0011] Canadian Regulatory Application No. 1,007,634, which was filed
with
Alberta's Energy Resources Conservation Board (ERCB) in April 1997, discusses
previous laboratory and field pilot data using xylene as a solvent. In these
cyclic solvent
tests, the solvent was injected as a liquid and reproduced as a liquid. Xylene
was
selected for use in these previous tests because it had demonstrated full
miscibility with
Cold Lake heavy oil at all mixture concentrations.
[0012] Another group of techniques is based on a continuous injection of
steam
through a first well to lower the viscosity of heavy oils and a continuous
production of
the heavy oil from a lower-lying second well. Such techniques may be termed
"steam
assisted gravity drainage," or SAGD. Various embodiments of the SAGD process
are
described in Canadian Patent No. 1,130,201 to Butler and its corresponding
U.S. Patent
No. 4,344,485.
[0013] In SAGD, two horizontal wells are completed into the reservoir. The
two wells
are first drilled vertically to different depths within the reservoir.
Thereafter, using
directional drilling technology, the two wells are extended in the horizontal
direction that
result in two horizontal wells, vertically spaced from, but otherwise
vertically aligned with
the other. Ideally, the production well is located above the base of the
reservoir but as
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close as practical to the bottom of the reservoir, and the injection well is
located
vertically 10 to 30 feet (3 to 10 meters) above the horizontal well used for
production.
[0014] The upper horizontal well is utilized as an injection well and is
supplied with
steam from the surface. The steam rises from the injection well, permeating
the
reservoir to form a drainage chamber that grows over time towards the top of
the
reservoir, thereby increasing the temperature within the reservoir. The steam,
and its
condensate, raise the temperature of the reservoir and consequently reduce the
viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam
will then
drain downward through the reservoir under the action of gravity and may flow
into the
lower production well, whereby these liquids can be pumped to the surface. At
the
surface of the well, the condensed steam and heavy oil are separated, and the
heavy oil
may be diluted with appropriate light hydrocarbons for transport by pipeline.
[0015] A number of variations of the SAGD process have been developed in an
attempt to increase the productivity of the process. Such processes may
include new
well placement techniques and tools used to enhance production of the heavy
oil. In
other variations, extensions similar to those used in CSS, such as including
solvents in
the process, have been made. For example, U.S. Pat. No. 6,230,814 to Nasr, et
al.,
teaches how the SAGD process can be further enhanced through the addition of
small
amounts of solvent to the injected steam. In addition, Butler, et al., "A New
Process
(Vapex) for Recovering Heavy Oils," JCPT, Vol. 30, No. 1, 97-106, Jan-Feb
1991,
teaches how solvent can be used instead of steam in a gravity drainage based
recovery
process to recover heavy oil from a subterranean reservoir.
[0016] A number of developments have focused on using solvents to lower the
temperature of the extraction process. For example, Canadian Patent No.
2,243,105, to
Mokrys, discloses a non-thermal vapor extraction method for the recovery of
hydrocarbons from deep, high-pressure hydrocarbon reservoirs. The reservoirs
may
have been previously exploited by cold flow or may be virgin deposits. The
target
reservoirs are underlain by active aquifers. A mixture of a light hydrocarbon
vapor
solvent, such as ethane, propane, and butane, with reservoir natural gas is
adjusted so
that the dew point of the light hydrocarbon solvent matches the temperature
and
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pressure conditions in the reservoir. The produced gas is analyzed for the
solvent
component, and enriched with the required amount of recycled solvent to match
the
dew point. The gas is then reintroduced into the reservoir as an injection
gas. Both the
recovered solvent and free gas are continuously circulated through the
reservoir. The
extraction can be accomplished by employing pairs of parallel horizontal
injection/production wells, in a similar fashion to SAGD.
[0017] Similarly, Canadian Patent No. 2,494,391 and Canadian Patent
Application
Publication No. 2,584,712 by Chung, et at., disclose a cold solvent-based
extraction
method for extracting heavy oil from a reservoir. The method involves forming
a solvent
fluid chamber by solvent fluid injection and heavy oil production using
combinations of
horizontal and/or vertical injection wells. The combination may increase the
recovery of
heavy oil contained in a reservoir.
[0018] Solvents may also be used in concert with steam addition to
increase the
efficiency of the steam in removing the heavy oils. U.S. Patent No. 6,230,814
to Nasr,
et at., discloses a method for enhancing heavy oil mobility using a steam
additive. The
method included injecting steam and an additive into the formation. The
additive
includes a non-aqueous fluid, selected so that the evaporation temperature of
the non-
aqueous fluid is within about 150 C of the steam temperature at the
operating
pressure. Suitable additives include C1 to C25 hydrocarbons. At least a
portion of the
additive condenses in the formation. The mobility of the heavy oil obtained
with the
steam and solvent combination is greater than that obtained using steam alone
under
substantially similar formation conditions.
[0019] In the case of recovery processes, such as SAGD, that include an
injection
and a production well drilled in close proximity to one another, a number of
techniques
have been described for the establishment of communication between the
injection well
and the production well. For example, Canadian Patent No. 1,304,287 to
Edmunds, et
at., teaches that, when two wells are in close proximity, e.g., 10 - 25 feet
(or 3 - 8
meters) apart, in a bitumen bearing reservoir, circulation of steam in both
wellbores will
heat the intervening reservoir sufficiently to allow the establishment of
fluid
communication between the injection and production wells.
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[0020] In addition, Canadian Patent No. 2,241,478 to China teaches
that, when
sufficient transmissibility exists in a reservoir, heated fluids can be
continuously injected
via the injection well and continuously produced via the production well. This
may result
in a degree of heating in the intervening reservoir that is sufficient to
allow for the
establishment of fluid communication between the injection well and the
production well.
[0021] A paper by Kisman, et al., entitled "Numerical Simulation of the
SAGD
Process in the Burnt Lake Oil Sands Lease", which was presented at the 1995
SPE
International Heavy Oil Symposium in Calgary, Alberta, Canada, in June of
1995,
teaches how cyclically injecting steam at sub-fracture pressures and producing
fluids
can be used to heat and partially deplete an intervening reservoir. The
heating of the
intervening reservoir may be sufficient to allow for the establishment of
fluid
communication between the injection well and the production well.
[0022] A paper by Donnelly entitled "Hilda Lake a Gravity Drainage
Success", which
was presented at the 1999 SPE International Thermal Operations and Heavy Oil
Symposium in Bakersfield, California in March of 1999, teaches how solvent
injection at
sub-fracture pressures can be used to reduce the viscosity of oil in an
intervening
reservoir. The reduction of the viscosity of the oil may be sufficient to
allow for direct
steam injection at sub-fracture pressures, which may result in the
establishment of fluid
communication between the injection well and the production well.
[0023] Canadian Patent Application Publication No. 2,698,898 by Pugh, et
al.,
teaches the injection of a solvent into one or both of an injection well and a
production
well at pressures too low to either compress the initial fluids present in the
reservoir or
dilate the pores of the reservoir rock. The injection of the solvent can be
used to
establish fluid communication between the injection well and the production
well.
However, according to this technique, the solvent must be injected at a
pressure no
higher than the initial reservoir pressure. Thus, no solvent would be able to
enter the
reservoir.
[0024] The recovery techniques discussed above may leave a substantial
remainder
of hydrocarbons in the reservoir. Further, the start-up processes for such
techniques
may be slow and unpredictable. For example, it may be difficult to predict the
location
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of initial fluid communication between two wells in a well pair, as well as
the amount
of time it may take to establish the initial fluid communication between the
two wells.
SUMMARY
[0025] An embodiment of the present techniques provides a system for
enhancing a start-up of a resource recovery process, comprising a well pair
comprising a horizontal production well at a first elevation and a horizontal
injection
well at a higher elevation, wherein the well pair is configured to force an
initial fluid
communication between the production well and the injection well to occur at a
selected region along a completion of the production well and a completion of
the
injection well, wherein the system is comprised of: a) a vertical separation,
a lateral
separation, or both, between the production well and the injection well that
is
reduced with respect to other vertical or lateral separations located between
the
production well and the injection well to force the initial fluid
communication to occur
at the selected region, or b) a temporary obstruction along the completion of
the
production well or the completion of the injection well, wherein the temporary
obstruction does not obstruct the selected region, and wherein the temporary
obstruction forces the initial fluid communication to occur at the selected
region.
[0026] Another embodiment provides a method for enhancing a start-up of a
resource recovery process, comprising: drilling a well pair through a
reservoir,
wherein the well pair comprises a horizontal production well at a first
elevation and
a horizontal injection well at a higher elevation; and establishing fluid
communication between the production well and the injection well by forcing an
initial fluid communication to occur at a selected region along a well
completion;
wherein establishing the fluid communication comprises: a) reducing a vertical
separation or a lateral separation, or both, between the production well and
the
injection well with respect to other vertical or lateral separations located
between
the production well and the injection well to force the initial fluid
communication to
occur at the selected region, or b) providing a temporary obstruction along
the
completion of the production well or the completion of the injection well,
wherein the
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temporary obstruction does not obstruct the selected region, and wherein the
temporary obstruction forces the initial fluid communication to occur at the
selected
region.
[0027]
Another embodiment provides a system for harvesting resources from a
reservoir, comprising: a
reservoir comprising hydrocarbons; and a well pair,
wherein the well pair comprises a horizontal production well and a horizontal
injection well, and wherein the well pair is configured to:
establish fluid
communication between the production well and the injection well by forcing an
initial fluid communication to occur at one or more selected regions along a
completion of the production well or a completion of the injection well, or
any
combination thereof; and enable a recovery of resources through a gravity
drainage
based recovery process once fluid communication has been established; wherein
the system comprises: a) a vertical separation or a lateral separation, or
both,
between the production well and the injection well that is reduced with
respect to
other vertical or lateral separations located between the production well and
the
injection well to force the initial fluid communication to occur at the
selected region,
or b) a temporary obstruction along the completion of the production well or
the
completion of the injection well, wherein the temporary obstruction does not
obstruct
the selected region, and wherein the temporary obstruction forces the initial
fluid
communication to occur at the selected region.
DESCRIPTION OF THE DRAWINGS
[0028]
The advantages of the present techniques are better understood by
referring to the following detailed description and the attached drawings, in
which:
[0029]
Fig. 1 is a drawing of a steam assisted gravity drainage (SAGD) process
used for accessing hydrocarbon resources in a reservoir;
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[0030] Fig. 2A is a schematic of a system for establishing fluid
communication
between a production well and an injection well;
[0031] Fig. 2B is a schematic of another system for establishing fluid
communication
between a production well and an injection well;
[0032] Fig. 3A is a schematic of a system for establishing an initial
fluid
communication between a production well and an injection well through the use
of a
selective, temporary obstruction covering a number of openings along a liner
of the
production well;
[0033] Fig. 3B is a schematic of a system for establishing the initial
fluid
communication between the production well and the injection well through the
use of a
selective, temporary obstruction covering a number of openings along the liner
of the
injection well;
[0034] Fig. 30 is a schematic of a system for establishing the initial
fluid
communication between the production well and the injection well through the
use of the
selective, temporary obstructions and on the liners and of both the production
well and
the injection well;
[0035] Fig. 4A is a schematic of a system for establishing an initial
fluid
communication between a production well and an injection well through a
modification
of a separation between the production well and the injection well at a
selected region;
[0036] Fig. 4B is a schematic of a system for establishing a location for
the initial
fluid communication between the production well and the injection well by
causing the
injection well to approach the production well at the selected region;
[0037] Fig. 4C is a schematic of a system for establishing the initial
fluid
communication between the production well and the injection well by having the
production well approach the injection well at a location;
[0038] Fig. 5 is a schematic of a system for establishing an initial
fluid
communication between a production well and an injection well through the
selective
injection of a solvent;
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[0039] Fig. 6 is a schematic of a system for establishing an initial
fluid
communication between a production well and an injection well through the
injection of
a solvent into the production well and the injection of steam into the
injection well;
[0040] Fig. 7A is a schematic of a system for establishing an initial
fluid
communication between a production well and an injection well through the use
of a
steam circulation process within the injection well;
[0041] Fig. 7B is a schematic of a system for establishing an initial
fluid
communication between the production well and the injection well through the
use of a
solvent injection process within the injection well;
[0042] Fig. 7C is a schematic of a system for establishing an initial fluid
communication between the production well and the injection well through the
use of a
solvent injection process within both the production well and the injection
well;
[0043] Fig. 8 is a schematic of a system for establishing complete fluid
communication between a production well and an injection well after the
initial fluid
communication has been established at a selected region;
[0044] Fig. 9 is a top view of a well pair with horizontal variations in
wellbore
separation; and
[0045] Fig. 10 shows a process flow diagram of a method for enhancing
the start-up
of a resource recovery process.
DETAILED DESCRIPTION
[0046] In the following detailed description section, specific
embodiments of the
present techniques are described. However, to the extent that the following
description
is specific to a particular embodiment or a particular use of the present
techniques, this
is intended to be for exemplary purposes only and simply provides a
description of the
exemplary embodiments. Accordingly, the techniques are not limited to the
specific
embodiments described below, but rather, include all alternatives,
modifications, and
equivalents falling within the true spirit and scope of the appended claims.
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[0047]
At the outset, for ease of reference, certain terms used in this
application and
their meanings as used in this context are set forth. To the extent a term
used herein is
not defined below, it should be given the broadest definition persons in the
pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below,
as all equivalents, synonyms, new developments, and terms or techniques that
serve
the same or a similar purpose are considered to be within the scope of the
present
claims.
[0048]
As used herein, the term "base" indicates a lower boundary of the
resources
in a reservoir that are practically recoverable, by a gravity-assisted
drainage technique,
for example, using an injected mobilizing fluid, such as steam, solvents, hot
water, gas,
and the like. The base may be considered a lower boundary of the pay interval.
The
lower boundary may be an impermeable rock layer, including, for example,
granite,
limestone, sandstone, shale, and the like. The lower boundary may also include
layers
that, while not impermeable, impede the formation of fluid communication
between a
well on one side and a well on the other side. Such layers may include broken
shale,
mud, silt, and the like. The resources within the reservoir may extend below
the base,
but the resources below the base may not be recoverable with gravity-assisted
techniques.
[0049]
"Bitumen" is a naturally occurring heavy oil material. It is often the
hydrocarbon component found in oil sands.
Bitumen can vary in composition
depending upon the degree of loss of more volatile components. It can vary
from a very
viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types
found in
bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical
bitumen
might be composed of:
19 wt. % aliphatics, which can range from 5 wt. %-30 wt. %, or higher;
19 wt. % asphaltenes, which can range from 5 wt. %-30 wt. %, or higher;
wt. % aromatics, which can range from 15 wt. %-50 wt. %, or higher;
32 wt. % resins, which can range from 15 wt. %-50 wt. %, or higher; and
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some amount of sulfur, which can range in excess of 7 wt. %.
In addition bitumen can contain some water and nitrogen compounds ranging from
less
than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while small, can
be
removed to avoid contamination of the product synthetic crude oil (SCO).
Nickel can
vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium
can
range from less than 200 ppm to more than 500 ppm. The percentage of the
hydrocarbon types found in bitumen can vary.
[0050] As used herein, "condensate" includes liquid water formed by the
condensation of steam. Steam may also entrain liquid water, in the form of
water
droplets. This entrained water may also be termed condensate, as it may arise
from
condensation of the steam, although the entrained water droplets may also
originate
from the incomplete conversion of liquid water to steam in a boiler.
[0051] A "development" is a project for the recovery of hydrocarbons
using
integrated surface facilities and long term planning. The development can be
directed
to a single hydrocarbon reservoir, although multiple proximate reservoirs may
be
included.
[0052] As used herein, "exemplary" means "serving as an example,
instance, or
illustration." Any embodiment described herein as "exemplary" is not to be
construed as
preferred or advantageous over other embodiments.
[0053] "Facility" as used in this description is a collection of physical
equipment
through which hydrocarbons and other fluids may be either produced from a
reservoir or
injected into a reservoir. A facility may also include equipment which can be
used to
control production or completion operations. In its broadest sense, the term
facility is
applied to any equipment that may be present along the flow path between a
reservoir
and its delivery outlets. Facilities may comprise production wells, injection
wells, well
tubulars, wellhead equipment, gathering lines, manifolds, pumps, compressors,
separators, surface flow lines, steam generation plants, extraction plants,
processing
plants, water treatment plants, and delivery outlets. In some instances, the
term
"surface facility" is used to distinguish those facilities other than wells.
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[0054] "Heavy oil" includes oils which are classified by the American
Petroleum
Institute (API), as heavy oils or extra heavy oils. In general, a heavy oil
has an API
gravity between 22.3 (density of 920 kg/m3 or 0.920 g/cm3) and 10.0 (density
of 1,000
kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less
than 10.00
(density greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a
source of
heavy oil includes oil sand or bituminous sand, which is a combination of
clay, sand,
water, and bitumen. The thermal recovery of heavy oils is based on the
viscosity
decrease of fluids with increasing temperature or solvent concentration. Once
the
viscosity is reduced, the mobilization of fluids by steam, hot water flooding,
or gravity is
possible. The reduced viscosity makes the drainage quicker and therefore
directly
contributes to the recovery rate.
[0055] A "hydrocarbon" is an organic compound that primarily includes
the elements
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other
elements may be present in small amounts. As used herein, hydrocarbons are
used to
refer to components found in bitumen, or other oil sands.
[0056] As discussed above, pore "dilation" refers to the enlargement of
pores in rock
or soil. The enlargement, or dilation, of such pores in rock or soil results
in the rock or
soil becoming more loosely packed.
[0057] As used herein, a "reservoir" is a subsurface rock or sand
formation from
which a production fluid can be harvested. The rock formation may include
sand,
granite, silica, carbonates, clays, and organic matter, such as oil, gas, or
coal, among
others. Reservoirs can vary in thickness from less than one foot (0.3048
meters) to
hundreds of feet (hundreds of meters).
[0058] The term "solvent" broadly refers to a substance or material
capable at least
in part of dissolving or dispersing one or more other materials or substances,
such as to
provide or form a solution. More specifically, as used herein, a solution is a
compound
that dissolves into and thus, reduces the viscosity of, naturally occurring
hydrocarbons.
[0059] As discussed above, "steam assisted gravity drainage" (SAGD) is
a thermal
recovery process in which steam is injected into a first well to lower a
viscosity of a
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heavy oil, and fluids are recovered from a second well. Both wells are usually
horizontal
in the formation and the first well lies above the second well. Accordingly,
the reduced
viscosity heavy oil flows down to the second well under the force of gravity,
although
pressure differential may provide some driving force in various applications.
[0060] "Substantial" when used in reference to a quantity or amount of a
material, or
a specific characteristic thereof, refers to an amount that is sufficient to
provide an effect
that the material or characteristic was intended to provide. The exact degree
of
deviation allowable may in some cases depend on the specific context.
[0061] As used herein, "thermal recovery processes" include any type of
hydrocarbon recovery process that uses a heat source to enhance the recovery,
for
example, by lowering the viscosity of a hydrocarbon. These processes may be
based
on heated water, wet steam, or dry steam, alone, or in any combinations.
Further, any
of these components may be combined with solvents to enhance the recovery.
Such
processes may include subsurface processes, such as cyclic steam stimulation
(CSS),
steamflooding, and SAGD, among others, and processes that use surface
processing
for the recovery, such as sub-surface mining and surface mining.
[0062] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit
into the subsurface. A wellbore may have a substantially circular cross
section or any
other cross-sectional shape, such as an oval, a square, a rectangle, a
triangle, or other
regular or irregular shapes. As used herein, the term "well," when referring
to an
opening in the formation, may be used interchangeably with the term
"wellbore."
[0063] As used herein, two locations in a reservoir are in "fluid
communication" when
a path for fluid flow exists between the locations. For example, the establish
of fluid
communication between a lower-lying production well and a higher injection
well may
allow material mobilized from a steam chamber above the injection well to flow
down to
the production well from collection and production. As used herein, a fluid
includes a
gas or a liquid and may include, for example, a produced hydrocarbon, an
injected
mobilizing fluid, or water, among other materials.
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[0064]
As used herein, a "cyclic recovery process" uses an intermittent injection
of a
mobilizing fluid selected to lower the viscosity of heavy oil in a hydrocarbon
reservoir.
The injected mobilizing fluid may include steam, solvents, gas, water, or any
combinations thereof. After a soak period, intended to allow the injected
material to
interact with the heavy oil in the reservoir, the material in the reservoir,
including the
mobilized heavy oil and some portion of the mobilizing agent may be harvested
from the
reservoir. Cyclic recovery processes use multiple recovery mechanisms, in
addition to
gravity drainage, early in the life of the process. The significance of these
additional
recovery mechanisms, for example dilation and compaction, solution gas drive,
water
flashing, and the like, declines as the recovery process matures. Practically
speaking,
gravity drainage is the dominant recovery mechanism in all mature thermal,
thermal-
solvent and solvent based recovery processes used to develop heavy oil and
bitumen
deposits. For this reason the approaches disclosed here are equally applicable
to all
recovery processes in which, at the current stage of depletion, gravity
drainage is the
dominant recovery mechanism.
Overview
[0065]
Embodiments described herein provide a method and systems for enhancing
the start-up of gravity drainage based recovery processes. Such a method and
systems
may be used to accelerate the start-up, provide for more predictable start-up
locations,
and reduce the costs for liner, tubular, or production fluid lift for gravity
drainage based
recovery processes.
[0066]
According to current start-up strategies, the specific location along the
liners
where fluid communication between the production and injection wells will
initially be
established is often random and unpredictable. Factors that influence the
specific
location include the local proximity of the injection well and the production
well, the local
geologic variability, the effectiveness of the steam rates used during
circulation to
propagate heat along the length of the liner, and the effectiveness of the
solvent in
flowing through, and subsequently propagating away from, the liner. Thus, it
is
desirable to ensure that well designs and operating procedures are flexible
enough to
accommodate and react to such uncertainties. For example, if the initial
fluid
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communication is established near the heels of the liner, i.e., the end of the
liner
adjacent to the intermediate casing string, it may be desirable to ensure that
steam can
be injected near the toe of the injection well liner, i.e., the end of the
liner furthest from
the intermediate casing string, to the keep the entire length of the
interjection well hot. It
may also be desirable to ensure that the remaining portions of the production
well liner
remain warm. This may be accomplished by forcing the fluids to travel to the
toe of the
production well liner before being produced from the well.
[0067] Embodiments disclosed herein provide a method and systems that
cause the
location of the initial fluid communication, i.e., the start-up location, to
be more
predictable. For example, in various embodiments, the separation between the
injection
well and the production well at the desired location, or locations, for
initial fluid
communication can be purposely reduced. In the case of a production well
having a
single pump located in the intermediate casing string just before the start,
or heel, of the
liner, the desired location for the establishment of initial fluid
communication may be
near the far end, or toe, of each of the liners. Such a location is used as
the basis for
the embodiments disclosed herein. However, it is to be understood that the
discussion
of the preferred start-up location as being near the toe of each of the liners
is used
merely for ease of discussion and is not intended to indicate that this
location is to be
used in every instance.
[0068] In various embodiments, a reduced separation between the injection
well liner
and the production well liner at each toe results in the faster conductive
heating of the
intervening reservoir at this location when the steam circulation approach is
used for
start-up. The reduced separation of the liners may also be combined with the
injection
of a viscosity reducing solvent, such as diesel, naphtha, or xylene,
preferentially at the
toes of the liners using, for example, small diameter coiled tubing string.
This may
result in a faster reduction of the viscosity of the oil present between the
wells at this
location. In addition, solvent injection may be performed independently of the
reduction
of the separation between the liners in order to increase the start-up rate,
or to decrease
the start-up costs.
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[0069]
In some embodiments, if the separation between the production well and the
injection well is sufficiently small, steam circulation or solvent injection
at a pressure
higher than the initial reservoir pressure in one well may be adequate to
establish
thermal communication, or fluid communication, between the two wells in an
acceptable
period of time. Furthermore, thermal communication between the two wells may
be
established in an acceptable period of time by using steam circulation in one
well and a
targeted solvent injection in the other well.
[0070]
The establishment of the initial fluid communication between the two wells
at
one or more desirable locations may allow the well design and associated
surface
facilities to be simplified and, thus, made less costly. For example, if
fluid
communication is established between the toes of the wells without having to
circulate
steam in the production well, the construction of steam injection tie-ins and
steam
metering for the production wells may be eliminated. Artificial lift systems
that currently
have maximum temperature constraints, such as electric submersible pumps
(ESPs)
and their associated electric cables, could be installed from the start of the
operations.
Steam could be injected via the injection well, communicate to the production
well via
the path established between the toes of the liners, and travel back along the
production
well liner to the pump location.
[0071]
This unidirectional flow path allows the temperatures near the ESPs to be
constrained by using conventional stream trap, or maximum temperature, control
calculation procedures that are applied at the pump location. Energy
efficiency of the
steam injected during the start-up phase is significantly enhanced as counter-
current
flow of steam and condensate no longer occurs in either wellbore.
[0072]
In addition, if fluid communication is established between the toe of each
of
the wells without having to circulate steam in the production well, the
production well
casing and liner sizes can be reduced, since a tubular for steam circulation
may not be
needed. The redirection of the production fluids to the toe of the production
well prior to
being produced as a means to ensure the entire production liner is heated
prior to start-
up may also be eliminated.
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[0073] Furthermore, the associated production fluid testing scheme can be
simplified. By including an artificial lift system from the start, the
pressure of the fluids
returning to the surface can be regulated to prevent the occurrence of a free
gas (e.g.,
solution, in situ generated steam, or solvent vapor) in the production stream.
The
volume and mass of the total production stream may be established using a mass
meter, and the fraction of hydrocarbon and condensed injectant can be
calculated by
understanding the individual temperature-density relationships of the two
components.
This measurement approach can be applied where sufficient density difference
naturally
exists between the two components.
[0074] Where sufficient density difference does not exist at the current
production
temperature, due to the different thermal expansion rates, it can be created
by
selectively heating or cooling the entire production stream, or a
representative slip
stream thereof. If more than one injectant is present, such as when both steam
and a
volatile solvent are used, identification of the quantities of the three
components can be
estimated by adding small to moderate pressure reduction downstream of the
mass
meter and measuring the resulting volume, temperature, and pressure of the
liquid and
vapor streams. Recombination calculations can then be used to estimate the
volumes
of the two non-aqueous components in the production stream.
[0075] In some embodiments, fluid communication is established between
the toe of
each of the injection and production wells without having to circulate steam
in the
injection well. In such cases, the steam injection capabilities for the
injection well could
be simplified. In addition, piping and measurement facilities for the
production of fluids
from the injection well may be eliminated. Further, the wellhead design can be
simplified, and the well casing and liner sizes can be reduced as two tubing
strings for
steam injection and fluid returns during the start-up phase may no longer be
included.
[0076] Alternatively, to create the desired location of initial fluid
communication
between the injection well and the production well, it is possible to obstruct
the liner
openings in all but the desired location in one, or both, of the liners. For
example, a
"throttled flow" liner with the desired screened sections left open in one or
both wells
may be combined with the option of solvent injection for establishing the
initial fluid
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communication in order to further simplify the well design. The toe tubing
string may no
longer be used to place the solvent at the desired location. Once the desired
communication is established, some or all of the remaining entry points in the
liners can
be unblocked.
[0077]
Using one or more of the strategies of the current invention, initial
communication between the injection well and the production well at the
desirable
location may result.
This outcome creates additional opportunities for further
optimization of the SAGD well design and, in some cases, enables an
accelerated start
of SAGD operations and oil production. Although embodiments disclosed herein
are
described in the context of the SAGD recovery process, it can be understood
that they
are equally applicable to all thermal, thermal-solvent, and solvent based
recovery
processes where gravity drainage is, or eventually becomes, the dominant
recovery
mechanism. Embodiments disclosed herein relate to a method and systems for
optimizing the depletion of a hydrocarbon resource when using thermal, thermal-
solvent, and solvent based recovery processes, as well as a series of well
designs and
operating procedures that allow this strategy to be successfully implemented.
SAGD Process
[0078]
Fig. 1 is a drawing of a steam assisted gravity drainage (SAGD) process
100
used for accessing hydrocarbon resources in a reservoir 102. In the SAGD
process
100, steam 104 can be injected through injection wells 106 to the reservoir
102. The
injection wells 106 may be horizontally drilled through the reservoir 102.
Production
wells 108 may be drilled horizontally through the reservoir 102. Generally, a
production
well 108 may be drilled under each injection well 106, but this is not
required in all
embodiments. The injection wells 106 and the production wells 108 can be
drilled from
the same pad 110 at the surface 112. This may make it easier for the
production well
108 to track the injection well 106. However, in some embodiments the wells
106 and
108 may be drilled from different pads 110.
[0079]
The injection of steam 104 into the injection wells 106 may result in the
mobilization of hydrocarbons 114, which may drain to the production wells 108
and be
removed to the surface 112 in a mixed stream 116 that can contain
hydrocarbons,
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condensate, and other materials, such as water, gases, and the like. As
described
herein, screen assemblies may be used on the injection wells 106, for example,
to
throttle the inflow of injectant vapor to the reservoir 102. Similarly, screen
assemblies
may be used on the production wells 108, for example, to decrease sand
entrainment.
[0080] The hydrocarbons 114 may form a triangular shaped drainage chamber
118
that has the production well 108 located at a lower apex. The mixed stream 116
from a
number of production wells 108 may be combined and sent to a processing
facility 120.
At the processing facility 120, the water and hydrocarbons 122 can be
separated, and
the hydrocarbons 122 sent on for further refining. Water from the separation
may be
recycled to a steam generation unit within the facility 120, with or without
further
treatment, and used to generate the steam 104 used for the SAGD process 100.
[0081] Each production well 108 and corresponding injection well 106
forms a well
pair 124. The production wells 108 and injection wells 106 may have a segment
that is
substantially horizontal and, in some circumstances, has a slight upward slope
from the
heel 126, at which the well branches to the surface 112, to the toe 128, at
which the well
ends. Each production well 108 may be designed such that it follows the
trajectory of
the corresponding injection well 106 along a base 130 of the reservoir.
[0082] In various embodiments described herein, each well pair 124 may
be
modified in any of a number of ways to allow for the establishment of the
initial fluid
communication between the production well 108 and the injection well 106 at a
selected
location, or region. For example, the vertical distance between the injection
well 106
and the production well 108 may be modified at a selected region 132 in order
to
increase the likelihood that the initial fluid communication will occur at the
selected
region 132. The wells 106 and 108 may have variations in the horizontal plane
that
cause increased or decreased separation between the wells 106 and 108.
Further,
certain regions of a completion 134 of the injection well 106 and a completion
136 of the
production well 108 may be obstructed, with a desired region 138 for the
initial fluid
communication remaining unobstructed. This may allow the initial fluid
communication
to occur at the desired region 138. Any number of other configurations or
techniques
may be used as discussed with respect to Figs. 2-10.
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Establishing Fluid Communication between a Production Well and an Injection
Well
[0083] Fig. 2A is a schematic of a system 200 for establishing fluid
communication
between a production well 202 and an injection well 204. Steam 206 may be
circulated
to a toe 208 of both the production well 202 and the injection well 204 using
a toe tubing
string 210. A combination 212 of steam and water may then be circulated from
the toe
208 of both the production well 202 and the injection well 204 back towards a
heel (not
shown) of each of the wells 202 and 204. An intervening area of a reservoir
214 located
between the production well 202 and the injection well 204 may be heated
through a
combination of heat conduction and fluid leak-off, e.g., convection. A
completion of
each well, such as a production liner 218 of the production well 202 and an
injection
liner 220 of the injection well 204 may also be perforated in order to allow
for the
establishment of fluid communication between the two wells 202 and 204, as
indicated
by the arrows 216.
[0084] Fig. 26 is a schematic of another system 222 for establishing
fluid
communication between a production well 224 and an injection well 226. Solvent
228
may be injected into the production well 224 and the injection well 226. The
solvent 228
may aid in the establishment of fluid communication between the production
well 224
and the injection well 226 by causing fluid to flow from the production well
224 to the
injection well 226 through an intervening area of a reservoir 230, as
indicated by the
arrows 232. A production liner 234 of the production well 224 and an injection
liner 236
of the injection well 226 may also be perforated in order to allow for the
establishment of
fluid communication between the two wells 224 and 226.
[0085] In contrast to the system 200, the system 222 may not have a toe
tubing
string, especially if the fluids contained in the wells 224 and 226 are
displaced by the
solvent 228 during the completion phase. Because the solvent 228 leaves the
production well 224 and the injection well 226 during the injection process,
the pressure
within the two wells 224 and 226 must be forced to exceed the initial
formation
pressure. In most circumstances, such pressure can be achieved by using the
pressure
head of the solvent 228 present inside the intermediate casing string, and by
adding
solvent as needed to maintain the pressure head using either a continuous feed
system
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or an intermediate feed system. In some circumstances it may be beneficial to
maintain
a pressurized gas head above the solvent column to ensure that the desired
solvent
pressure is maintained.
[0086] While the systems 200 and 222 provide for the establishment of
fluid
communication between a production well and an injection well, the location of
the initial
fluid communication is uncertain with these approaches. Thus, it may be
difficult to
predict or control the start-up of the hydrocarbon recovery process. It is
often desirable
to achieve a faster start-up of the hydrocarbon recovery process with a more
predictable
start-up location, e.g., location of initial fluid communication between the
two wells.
Establishing Fluid Communication at a Selected Region
[0087] Fig. 3A is a schematic of a system 300 for establishing an
initial fluid
communication between a production well 302 and an injection well 304 through
the use
of a selective, temporary obstruction 306 covering a number of openings along
a liner
308 of the production well 302. Toe tubing strings 310 may also be used within
each of
the wells 302 and 304 in accordance with a steam circulation startup technique
to
ensure that the location of the initial fluid communication between the
production well
302 and the injection well 304 is established at a selected region 312, as
indicated by
the arrow 314. For example, in some embodiments, the selected region 312 may
be
between the toe of each of the liners 308 and 316 of the production well 302
and the
injection well 304, respectively. In various embodiments, the selective,
temporary
obstruction 306 covering portions of the liner 308 of the production well 302
may
prevent the initial fluid communication from occurring anywhere other than the
selected
region 312. For example, as shown in Fig. 3A, the selected region 312 may be
the only
location along the liner 308 of the production well 302 that is not blocked,
or obstructed,
from communicating with the surrounding environment.
[0088] Fig. 3B is a schematic of a system 318 for establishing the
initial fluid
communication between the production well 302 and the injection well 304
through the
use of a selective, temporary obstruction 320 covering a number of openings
along the
liner 316 of the injection well 304. In various embodiments, the selective,
temporary
obstruction 320 on the liner 316 of the injection well 304 may prevent the
initial fluid
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communication from occurring anywhere other than the selected region 312. For
example, as shown in Fig. 3B, the selected region 312 may be the only location
along
the liner 316 of the injection well 304 that is not blocked, or obstructed,
from
communicating with the surrounding environment.
[0089] Fig. 3C is a schematic of a system 322 for establishing the initial
fluid
communication between the production well 302 and the injection well 304
through the
use of the selective, temporary obstructions 306 and 320 on the liners 308 and
316 of
both the production well 302 and the injection well 304. In various
embodiments, the
selective, temporary obstructions 306 and 320 on the liners 308 and 316 of the
two
wells 302 and 304 may prevent the initial fluid communication from occurring
anywhere
other than the selected region 312. For example, as shown in Fig. 3C, the
selected
region 312 may be the only location along the liners 308 and 316 of the
production well
302 and the injection well 304, respectively, that is not blocked, or
obstructed, from
communicating with the surrounding environment.
[0090] According to the systems 300, 318, and 322, the selective,
temporary ,
obstructions 306 and 320 may be removed once the initial fluid communication
between
the production well 302 and the injection well 304 has been established. The
selective,
temporary obstructions 306 and 320 may include, for example, scab liners or
shear
plugs that are to be physically removed, acidizable plugs that are to be
chemically
removed, a wax coating on the liner that is to be removed by heating, or a
material than
can be melted or dissolved by steam or water. In addition, the selective,
temporary
obstructions 306 and 320 may be provided by the presence of an alternate fluid
type in
the wellbore, as discussed further with respect to Fig 5.
[0091] Once the selective, temporary obstructions 306 and 320 are
removed,
secondary locations of fluid communication between the production well 302 and
the
injection well 304 may be rapidly established. In some embodiments, the
portions of the
liners 308 and 316 of the production well 302 and the injection well 304,
respectively,
that are covered by the selective, temporary obstructions 306 and 320 may be
continuously heated in order to aid in the establishment of the secondary
locations of
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fluid communication after the selective, temporary obstructions 306 and 320
are
removed.
[0092] Fig. 4A is a schematic of a system 400 for establishing an
initial fluid
communication between a production well 402 and an injection well 404 through
a
modification of a separation between the production well 402 and the injection
well 404
at a selected region 406. Toe tubing strings 408 may also be used within each
of the
wells 402 and 404 in accordance with a steam circulation startup technique to
ensure
that the location of the initial fluid communication between the production
well 402 and
the injection well 404 is established at the selected region 406, as indicated
by the
arrow 410.
[0093] In various embodiments, a vertical separation or a lateral
separation, or both,
between the production well 402 and the injection well 404 may be selectively
adjusted
according to the specific application. The separation may be adjusted such
that the
initial fluid communication between the production well 402 and the injection
well 404 is
more likely to occur at the selected region 406. For example, as shown in Fig.
4A,. the
selected region 406 may be at the toe of each of the liners of the production
well 402
and the injection well 404, and a distance of the injection well 404 from the
production
well 402 may be modified in the selected region 406 to increase the likelihood
that the
initial fluid communication between the two wells 402 and 404 will occur near
the toes.
Further, in various embodiments, a separation between the production well 402
and the
injection well 404 may be modified in several selected regions in order to
allow for an
fluid communication to develop between the two wells 402 and 404 at each of
the
selected regions.
[0094] Fig. 4B is a schematic of a system 412 for establishing a
location for the initial
fluid communication between the production well 402 and the injection well 404
by
causing the injection well 404 to approach the production well 402 at the
selected region
406. The system 412 may also include selective, temporary obstructions along
the
liners of one or both of the wells 402 and 404. Such obstructions may aid in
the
establishment of the initial fluid communication at the selected region 406.
For
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example, as shown in Fig. 4B, the system 412 may include a selective,
temporary
obstruction 414 along a liner 416 of the production well 402.
[0095] Fig. 4C is a schematic of a system 418 for establishing the
initial fluid
communication between the production well 402 and the injection well 404 by
having
the production well 402 approach the injection well 404 at a location 420. The
modification of the separation between the production well 402 and the
injection well
404 at the location 420 may cause the initial fluid communication between the
two wells
402 and 404 to be established at a selected region 422. For example, the
selected
region 422 may be a specific location along the liner 416 of the production
well 402.
The modification of the separation between the production well 402 and the
injection
well 404 at the location 420 may cause fluid to flow from the location 420 to
the selected
region 422 through an intervening region of a reservoir 424, as indicated by
the arrow
426. Further, in some embodiments, a selective, temporary obstruction 428
along the
liner 416 of the production well 402 in the location 420 may prevent the
initial fluid
communication from occurring at the location 420. Conductive heating, along
the
outside of the liner 416 of the production well 402 will allow fluid flow from
the location
420 to the selected region 422. In this case, the obstruction may be permanent
to block
the formation of a direct steam path between the injection well 404 and the
production
well 402.
[0096] Fig. 5 is a schematic of a system 500 for establishing an initial
fluid
communication between a production well 502 and an injection well 504 through
the
selective injection of a solvent 506. A toe tubing string 508 may be used in
each of the
two wells 502 and 504 to selectively inject the solvent 506 into a liner 510
of the
production well 502 and a liner 512 of the injection well 504. In some
embodiments,
backflow of the solvent 506 along one or both of the liners 510 and 512 is
impeded
though the maintenance of a water fill in the liner annulus, resulting in a
solvent-water
interface 513. Further, in various embodiments, the locations of the toe
tubing strings
508 may be such that the injection of the solvent 506 causes the initial fluid
communication between the production well 502 and the injection well 504 to
occur at a
selected region 514, as indicated by the arrow 516.
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[0097] As more than a year can pass between the drilling of a well pair and
the
completion of the surface facilities that are used to allow steam injection
and fluid
production, this extended period of time can be used for the establishment of
fluid
communication using a solvent based start-up technique. As the length of the
available
time period increases, a lower injection pressure and solvent injection rate
can be used,
allowing for a better mixing of the solvent and oil in the near wellbore
reservoir region.
While this approach may seem to be a slower procedure, it does achieve the
desired
result of allowing the well pairs to go directly to normal SAGD operations
once the
required steam generation and fluids processing surface facilities are
available.
[0098] Fig. 6 is a schematic of a system 600 for establishing an initial
fluid
communication between a production well 602 and an injection well 604 through
the
injection of a solvent 606 into the production well 602 and the injection of
steam 608 into
the injection well 604. For example, a steam circulation process may be
utilized to
inject the steam 608 into the injection well 604, while a solvent injection
process may be
utilized to inject the solvent 606 into the production well 602. In some
embodiments, a
toe tubing string 610 within the injection well 604 may be used to circulate
the steam
608. In various embodiments, the simultaneous implementation of the steam
circulation
process and the solvent injection process may allow for the rapid
establishment of the
initial fluid communication between the production well 602 and the injection
well 604 at
a selected region 612, as indicated by the arrow 614. Further, in some
embodiments, a
selective, temporary obstruction 616 along a liner 618 of the injection well
604 helps to
ensure that the initial fluid communication occurs at the selected region.
[0099] In some embodiments, the configuration of the system 600 may cause the
production well 602 to remain relatively cool, allowing an artificial lift
system that has a
maximum temperature limitation to be installed as part of the initial
completion process.
This may reduce the overall cost of the completion process.
[0100] Fig. 7A is a schematic of a system 700 for establishing an
initial fluid
communication between a production well 702 and an injection well 704 through
the use
of a steam circulation process within the injection well 704. Steam 706 may be
injected
into the injection well 704 though a toe tubing string 708. A separation
between the
CA 02766838 2012-02-06
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production well 702 and the injection well 704 at a selected region 710 may be
adjusted
such that the selected region 710 is the location with the minimum distance
between the
two wells 702 and 704. The steam circulation process combined with the
modification
of the separation between the two wells 702 and 704 at the selected region 710
may
ensure that the initial fluid communication between the two wells 702 and 704
is
established at the selected region 710, as indicated by the arrow 712. In
various
embodiments, the system 700 may reduce the overall cost of the completion
process,
since the production well 702 may be a simple wellbore without any
modifications.
[0101] Fig. 7B is a schematic of a system 714 for establishing an
initial fluid
communication between the production well 702 and the injection well 704
through the
use of a solvent injection process within the injection well 704. The solvent
injection
process may involve the injection of a solvent 716 into the injection well 704
in order to
aid in the establishment of the initial fluid communication between the two
wells 702 and
704. As described above with respect to Fig. 7A, a separation between the
production
well 702 and the injection well 704 at the selected region 710 may be adjusted
such that
the selected region 710 is the location with the minimum distance between the
two wells
702 and 704. The solvent injection process combined with the modification of
the
separation between the two wells 702 and 704 at the selected region 710 may
ensure
that the initial fluid communication between the two wells 702 and 704 is
established at
the selected region 710, as indicated by the arrow 712. In various
embodiments, the
system 714 may also reduce the overall cost of the completion process, since
both the
injection well 704 and the production well 702 may be a simple wellbore
without any
modifications.
[0102] Fig. 7C is a schematic of a system 718 for establishing an
initial fluid
communication between the production well 702 and the injection well 704
through the
use of a solvent injection process within both the production well 702 and the
injection
well 704. The solvent injection process may involve the injection of the
solvent 716 into
the production well 702 and the injection well 704 in order to aid in the
establishment of
the initial fluid communication between the two wells 702 and 704. As
described above
with respect to Figs. 7A and 7B, a separation between the production well 702
and the
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injection well 704 at the selected region 710 may be adjusted such that the
selected
region 710 is the location with the minimum distance between the two wells 702
and
704. The solvent injection process within both of the wells 702 and 704
combined with
the modification of the separation between the two wells 702 and 704 at the
selected
region 710 may ensure that the initial fluid communication between the two
wells 702
and 704 is established at the selected region 710, as indicated by the arrow
712. In
various embodiments, the system 718 may also reduce the overall cost of the
completion process, since both the injection well 704 and the production well
702 may
be a simple wellbore without any modifications.
[0103] Fig. 8 is a schematic of a system 800 for establishing complete
fluid
communication between a production well 802 and an injection well 804 after
the initial
fluid communication has been established at a selected region 806. In various
embodiments, once the initial fluid communication has been established between
the
production well 802 and the injection well 804 at the selected region 806, as
indicated
by the arrow 808, the start-up of the SAGD process can continue with steam 810
being
injected via the injection well 804, and steam and condensate 812 being
returned via
the production well 802. In some embodiments, a steam trap control is applied
at the
heel of the liner of the production well 802. Over time, complete, or nearly
complete,
fluid communication will be established between the production well 802 and
the
injection well 804.
[0104] While a toe tubing string is not shown in Fig. 8, alternate
configurations could
include a toe tubing string in the injection well 804 for the injection of the
steam 810.
For such configurations, the injection of the steam 810 may occur via the
annular space,
via the toe tubing string itself, or via both the annular space and the toe
tubing string,
depending on the specific application. In addition, the injection of the steam
810 may
occur via a toe tubing string that has a blocked toe end and a series of small
diameter
openings along its length to distribute the steam 810 along the length of the
injection
well 804.
[0105] Fig. 9 is a top view of a well pair 900 with horizontal
variations in wellbore
separation. The well pair 900 may include a lower production well 902 and an
upper
27
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injection well 904. The desired variation in the wellbore separation may be
generated
by changing the lateral separation between the lower production well 902 and
the upper
injection well 904. This may create one or more intervals 906 for the
preferential
establishment of initial fluid communication between the lower production well
902 and
the upper injection well 904. In some embodiments, the one or more intervals
for the
preferential establishment of initial fluid communication may be established
by
manipulating both the lateral separation and the vertical separation between
the lower
production well 902 and the upper injection well 904.
Method for Enhancing the Start-Up of Resource Recovery Processes
[0106] Fig. 10 shows a process flow diagram of a method 1000 for enhancing
the
start-up of a resource recovery process. In some embodiments, the method 1000
may
accelerate the start-up of the resource recovery process, and may also
increase the
predictability of the start-up location, .i.e., the location of initial fluid
communication, for
the resource recovery process. The resource recovery process may be a thermal
based gravity drainage process, a thermal-solvent based gravity drainage
process, or a
solvent based gravity drainage process, among others. In addition, the
resource
recovery process may be a gravity drainage based recovery process. In various
embodiments, the resource to be recovered includes hydrocarbons.
[0107]
The method 1000 begins at block 1002 with the drilling of a well pair
through
a reservoir. The well pair may include a production well at a first elevation
and an
injection well at a higher elevation. The trajectories of the production well
and the
injection well may be as closely aligned as possible in order to maintain an
approximate
degree of separation between the two wells.
[0108]
At block 1004, fluid communication between the production well and the
injection well may be established by forcing an initial fluid communication to
occur at a
selected region along the well completion. For example, the initial fluid
communication
may be forced to occur at a selected region along a liner of the production
well or a liner
of the injection well. The selected region may be a desired location for the
initial fluid
communication between the production well and the injection well.
In various
embodiments, the selected region is the toe of the liner of the production
well or the
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injection well, or both. In addition, the well completion may be a completion
of the
production well or a completion of the injection well, or both.
[0109] In some embodiments, establishing the fluid communication
between the two
wells includes adjusting a separation between the production well and the
injection well
at the selected region. For example, a vertical separation or a lateral
separation, or
both, between the two wells may be adjusted. Furthermore, the separation
between the
production well and the injection well may be adjusted at several locations
along the
completion of the production well and the completion of the injection well in
order to
force the initial fluid communication to occur at several selected regions.
[0110] In some embodiments, establishing the fluid communication between
the two
wells includes selectively and temporarily obstructing one or more regions of
a
completion of the production well or the injection well, or both, in order to
ensure that
the initial fluid communication occurs at the selected region. For example, a
liner of a
production well may be obstructed everywhere except at the selected region, so
that the
initial fluid communication between the production well and an injection well
may occur
only at the selected region. In addition, in some embodiments, multiple
selective,
temporary obstructions are used to ensure that the initial fluid communication
occurs at
several selected regions.
[0111] Further, in some embodiments, establishing the fluid
communication between
the two wells includes selectively injecting a solvent or steam, or any
combination
thereof, into the production well or the injection well, or both, to provide
for the
establishment of the initial fluid communication at the selected region. For
example, a
toe tubing string within the production well or the injection well, or both,
may be used to
selectively inject the solvent or the steam into the production well or the
injection well at
the selected region. In various embodiment, the solvent is injected into the
production
well or the injection well using a solvent injection system, while the steam
is injected into
the production well or the injection well using a steam injection system.
According to an
exemplary configuration, the solvent is injected into the production well, and
the steam
is injected into the injection well, to accelerate the establishment of the
initial fluid
communication at the selected region.
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[0112]
Fig. 10 is not intended to indicate that all of the steps of the method
1000 are
to be included in every case. Moreover, any number of additional steps may be
included according to the specific application. For example, once the initial
fluid
communication between the production well and the injection well has been
established
at block 1004, additional fluid communication between the two wells may
continue along
both directions of the completion of the production well and the completion of
the
injection well starting from the region of the initial fluid communication.
Once complete,
or nearly complete, fluid communication has been established, resources may be
recovered from the reservoir through a gravity drainage based recovery
process.
Furthermore, it is to be understood that, according to the method 1000, the
initial fluid
communication may not occur directly at a selected region but, rather, may
occur in
proximity to the selected region.
[0113]
In some embodiments, the method 1000 does not result in the acceleration
of
the establishment of the fluid communication between the production well and
the
injection well. Rather, the method 1000 may actually slow down the timing of
the initial
fluid communication, but may still result in an acceleration of the conversion
to normal
SAGD operations. In addition, the method 1000 may not result in an appreciable
change in timing but, instead, may allow for significant cost savings with
respect to well
and surface equipment design, for example.
[0114]
The above-described embodiments of the invention are intended to be
examples only. Alterations, modifications, and variations can be effected to
the
particular embodiments by those of ordinary skill in the art without departing
from the
scope of the invention, which is defined solely by the claims appended hereto.
Embodiments
[0115]
Embodiments of the invention may include any combinations of the methods
and systems shown in the following numbered paragraphs. This is not to be
considered
a complete listing of all possible embodiments, as any number of variations
can be
envisioned from the description above.
CA 02766838 2015-10-26
[0115a] As set forth above, provided herein is a system for enhancing
a start-up of
a resource recovery process, including a well pair including a production well
at a first
elevation and an injection well at a higher elevation, wherein the well pair
is configured
to force an initial fluid communication between the production well and the
injection well
to occur at a selected region along a completion of the production well and a
completion
of the injection well.
[0115b] The resource recovery process may include a thermal based
gravity
drainage process, a thermal-solvent based gravity drainage process, or a
solvent based
gravity drainage process.
[0115c] The selected region may include a toe of a liner of the production
well or a
toe of a liner of the injection well, or both.
[0115d] The selected region may include a desired location for the
initial fluid
communication between the production well and the injection well.
[0115e] A vertical separation or a lateral separation, or both,
between the
production well and the injection well may be modified to force the initial
fluid
communication to occur at the selected region.
[0115f] The vertical separation or the lateral separation, or both,
between the
production well and the injection well may be modified at several locations to
force the
initial fluid communication to occur at several selected regions.
[0115g] The system may include a temporary obstruction along the completion
of
the production well or the completion of the injection well, wherein the
temporary
obstruction does not obstruct the selected region, and wherein the temporary
obstruction forces the initial fluid communication to occur at the selected
region.
[0115h] The system may include a solvent injection system for
selectively injecting
a solvent into the production well or the injection well, or both, to force
the initial fluid
communication to occur at the selected region.
[0115i] The system may include a steam injection system for
selectively injecting
steam into the production well or the injection well, or both, to force the
initial fluid
communication to occur at the selected region.
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[0115j] Further provided herein is a method for enhancing a start-up
of a resource
recovery process, including: drilling a well pair through a reservoir, wherein
the well pair
includes a production well at a first elevation and an injection well at a
higher elevation;
and establishing fluid communication between the production well and the
injection well
by forcing an initial fluid communication to occur at a selected region along
a well
completion.
[0115k] The selected region may include a toe of a liner of the
production well or a
toe of a liner of the injection well, or both.
[01151] The selected region may include a desired location for the
initial fluid
communication between the production well and the injection well.
[0115m] The well completion may include a completion of the production
well or a
completion of the injection well, or any combination thereof.
[0115n] Establishing the initial fluid communication may include
adjusting a
separation between the production well and the injection well at the selected
region.
[01150] The method may include adjusting the separation between the
production
well and the injection well at several locations along a completion of the
production well
and a completion of the injection well to force the initial fluid
communication to occur at
several selected regions.
[0115p] The method may include adjusting a vertical separation or a
lateral
separation, or any combination thereof, between the production well and the
injection
well at the selected region.
[0115q] Establishing the initial fluid communication may include
selectively and
temporarily obstructing one or more regions of a completion of the production
well or the
injection well, or both, in order to ensure that the initial fluid
communication occurs at
the selected region.
[0115r] Establishing the initial fluid communication may include
selectively
injecting a solvent or steam, or any combination thereof, into the production
well or the
injection well, or both, to accelerate an establishment of the initial fluid
communication
at the selected region.
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=
[0115s] The
method may include inserting a toe tubing string into a liner of the
production well or a liner of the injection well, or both, wherein the toe
tubing string is
used to selectively inject the solvent or the steam, or any combination
thereof, into the
production well or the injection well, or both, at the selected region.
[0115t] The
method may include injecting the solvent into the production well and
injecting the steam into the injection well to provide for an establishment of
the initial
fluid communication at the selected region.
[0115u] The
resource recovery process may include a thermal, thermal-solvent, or
solvent based recovery process.
[0115v] The
resource recovery process may include a gravity drainage based
recovery process.
[0115w] Also
provided herein is a system for harvesting resources from a reservoir,
including: a reservoir including hydrocarbons; and a well pair, wherein the
well pair
includes a production well and an injection well, and wherein the well pair is
configured
to: establish fluid communication between the production well and the
injection well by
forcing an initial fluid communication to occur at one or more selected
regions along a
completion of the production well or a completion of the injection well, or
any
combination thereof; and enable a recovery of resources through a gravity
drainage
based recovery process once fluid communication has been established.
[0115x] A
lateral separation or a vertical separation, or both, between the
production well and the injection well may be changed at the one or more
selected
regions to force the initial fluid communication to occur in proximity to the
one or more
selected regions.
[0115y] The
system may include a solvent injection system for selectively injecting
a solvent into the production well or the injection well, or both, at the one
or more
selected regions to force the initial fluid communication to occur at the one
or more
selected regions.
[0115z] The
solvent injection system may include a toe tubing string for selectively
injecting the solvent at the one or more selected regions.
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[0115aa]
The system may include a steam injection system for selectively injecting
steam into the production well or the injection well, or both, at the one or
more selected
regions to force the initial fluid communication to occur at the one or more
selected
regions.
[0115ab]
The system may include one or more temporary and selective
obstructions within the completion of the production well and the completion
of the
injection well, wherein the one or more temporary and selective obstructions
force the
initial fluid communication to occur at the one or more selected regions.
[0115ac]
The resources of any of the foregoing systems may include hydrocarbons.
[0115ad]
The fluid communication between the production well and the injection
well may begin with the initial fluid communication at the one or more
selected regions
and continues along both directions of the completion of the production well
and the
completion of the injection well starting from the one or more selected
regions.
[0016]
While the present techniques may be susceptible to various modifications
and
alternative forms, the embodiments discussed above have been shown only by way
of
example. However, it should again be understood that the techniques is not
intended to
be limited to the particular embodiments disclosed herein.
Indeed, the present
techniques include all alternatives, modifications, and equivalents falling
within the
scope of the appended claims.
34
